Methods for Pillar Placement in Fracturing

ABSTRACT

Methods for placing proppant aggregates using a diverting fluid comprising a diverting agent and a packing fluid. Proppant aggregates are introduced into a fracture that is fluidically connected to a wellbore through a plurality of perforations. Thereafter, a diverting diverting fluid is introduced into the wellbore to seal some perforations and leave at least one unsealed perforation. Once some perforations are sealed, a packing fluid is introduced into the fracture through the at least one unsealed perforation, thereby forming the proppant aggregates to move together and form a proppant bed within the fracture.

BACKGROUND

The present invention relates to fracturing operations and, moreparticularly, to compositions and methods related to proppant pillarplacement using diverting agents.

In a typical hydraulic fracturing operation, a proppant (sometimesreferred to as a “propping agent”) is suspended in a portion of afracturing fluid, and may then be transported and deposited in fractureswithin the subterranean formation. Proppants are traditionallyparticulates that collectively form proppant packs that can serve as aphysical barrier to prevent the fractures from fully closing so thatconductive channels are formed around the proppants through whichproduced hydrocarbons can flow. Thus, the degree of success of afracturing operation depends, at least in part, upon the resultantfracture porosity and conductivity once the fracturing operation isstopped and production is begun. Typical hydraulic fracturing operationsplace a large volume of proppants into a fracture to form a relativelyhomogeneous proppant pack within the fracture. The porosity of theresultant packed, propped fracture is then at least partially related tothe interconnected interstitial spaces between the abutting proppantparticulates.

An alternative fracturing approach (i.e., heterogeneous proppantplacement) involves placing a significantly reduced volume of proppantsin a fracture to create a propped fracture having high porosity,fracture permeability, and/or conductivity. The reduced volume ofproppants may be consolidated, in certain conditions, to form individualaggregate structures (e.g., proppant pillars) that can be used to abutthe fracture. As used herein, the term “proppant pillar” and relatedterms such as “proppant aggregate” refer to a coherent cluster ofproppants that remains a coherent body that may be used to prop afracture. Proppant aggregates generally do not become dispersed intosmaller bodies without application of significant shear. A proppantaggregate may be formed, for example, by coating individual proppantswith an adhesive substance such that the proppants have a tendency tocreate clusters or aggregates. As used herein, the term “proppants”refers to the various individual proppant forms described in thisdisclosure.

Heterogeneous proppant placement typically involves pumping differenttypes of slurries or fluids in discrete intervals. This can providehigher conductivity fractures than those obtained from conventionaltreatments, and may increase fracture porosity by forming aheterogeneous proppant pack, that is, a random (or heterogeneous)distribution of proppant pillars. The proppant pillars should havesufficient strength to hold the fracture partially open under closurestress. The open space between proppant pillars forms a network ofinterconnected open channels, available for the flow of fluids into thewellbore. This results in a significant increase of the effectivehydraulic conductivity and porosity of the overall fracture.

However, there are certain technical challenges that limit theusefulness of proppant pillars in fracturing operations. For example,proppant settling can be a significant problem for heterogeneousproppant placement operations that use reduced volumes of proppants.Thus, settling can lead to fracture closure, particularly at or near thetop portion of a fracture, which can significantly lower theconductivity and porosity of the propped fracture.

SUMMARY OF THE INVENTION

The present invention relates to fracturing operations and, moreparticularly, to compositions and methods related to proppant pillarplacement using diverting agents.

In some embodiments, the present invention provides a method comprising:providing proppant aggregates; a diverting fluid comprising a divertingagent; and a packing fluid; introducing the proppant aggregates into afracture that is fluidically connected to a wellbore through a pluralityof perforations; introducing the diverting fluid into the wellborethereby forming at least one sealed perforation and leaving at least oneunsealed perforation; and introducing the packing fluid into thefracture through the at least one unsealed perforation thereby allowingthe proppant aggregates to form a proppant bed within the fracture.

In other embodiments, the present invention provides a methodcomprising: providing proppant aggregates; a diverting fluid comprisinga degradable diverting agent; and a packing fluid; introducing theproppant aggregates into a fracture that is fluidically connected to awellbore through a plurality of perforations; introducing the divertingfluid into the wellbore thereby forming at least one sealed perforationand leaving at least one unsealed perforation; introducing the packingfluid into the fracture through the at least one unsealed perforationthereby allowing the proppant aggregates to form a proppant bed withinthe fracture; and allowing the degradable diverting agent to degradethereby unsealing the at least one perforation.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof the preferred embodiments that follows.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent invention, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, as willoccur to those skilled in the art and having the benefit of thisdisclosure.

FIGS. 1A-1C schematically illustrate aspects of proppant pillarplacement according to one or more embodiments.

DETAILED DESCRIPTION

The present invention relates to fracturing operations and, moreparticularly, to compositions and methods related to proppant pillarplacement using diverting agents.

While the various embodiments of the present invention are discussed indetail below, it should be appreciated that the present inventionprovides many applicable inventive concepts which can be embodied in awide variety of specific contexts. The specific embodiments discussedherein are merely illustrative of specific ways to make and use theinvention, and do not delimit the scope of the present invention. Tofacilitate a better understanding of the present invention, thefollowing examples of preferred or representative embodiments are given.

The present invention provides compositions and methods for selectivelydiverting fluids during a fracturing operation, which can reduce thesettling of particulates (e.g., proppants) within a fracture. As aresult, proppants including aggregates of proppants can be distributedmore evenly within the fracture, particularly at or near the top portionof a fracture. When a fracture closes on a more evenly distributedaggregates of proppants, a higher porosity propped fracture can beformed.

Referring to FIG. 1A, proppant aggregates 100 suspended in fluid havebeen transported into fracture 110 through perforations 120 (a-d) on acasing or liner 130 that spans the wellbore, including zones containingthe fracture 110. Perforations can be formed by any suitable meansincluding, but not limited to, jet perforating guns equipped with shapedexplosive charges, abrasive jetting, and high-pressure fluid jetting.Over time, proppant aggregates can settle due to factors such asgravitational force (prior to closing of the fracture), which can leadto partial or possibly full closure of the upper portion of thefracture, which can significantly compromise the capacity to recoverfluids. As used herein, “settling” and related terms (e.g., “sagging”)refer to the phenomena of suspended particles falling in liquid.

Referring to FIG. 1B, a degradable diverting agent has been used toselectively seal one or more perforations 120 a, 120 b, and 120 c, whileleaving open 120 d to hydraulically connect the fracture 110 and theinside of casing 130. As illustrated, a majority of the perforations 120on casing/liner 130 have been sealed by the diverting agent so that onlya single perforation 120 d remains unsealed. It should be understoodthat the exact number of sealed and unsealed perforations, including theexact ratio of sealed to unsealed perforations, may be varied withoutdeparting from the scope of the present invention. In some embodiments,more that one perforation may be left unsealed. The unsealedperforations, such as 120 d in FIG. 1B, are typically located at or nearthe bottom portion 140 of the fracture 110 while the sealed perforationsare typically located above the unsealed perforations. However, otherconfigurations may be compatible with the one or more embodimentsdescribed herein. Moreover, while it may be desirable that the divertingagent fully seals the targeted perforations so that fluidiccommunication between the fracture and casing/liner is completely cutoff, it should be understood that the present invention can bepracticed, in some embodiments, even when the targeted perforations arepartially sealed.

Next, referring to FIG. 1C, a packing fluid according to one or moreembodiments comprising relatively high volumes of proppants 100 isintroduced into the fracture 110 through the unsealed perforation(s) 120d such that a homogeneous proppant bed 150 is formed at the bottomportion 140 of the fracture 110. The homogeneous proppant bed 150prevents proppant aggregates 100 from settling to the bottom portion140. Consequently, free particulates or aggregates of particulatessuspended within the fracture are generally displaced towards the topportion of the fracture 110. Once the fracture closes on the proppantaggregates and the proppant bed below, a high porosity fracture isformed.

Whenever the terms “bottom” or “top” are used to describe theorientation of the height of a fracture, “bottom” typically refers tothe portion of the fracture that the proppants generally settle towardswhile “top” may be determined by its orientation in relation to theabove-defined “bottom.”

Once the proppant aggregates and proppant bed are in place, thediverting agents used to seal the perforations 120 may be degraded orotherwise removed. Hydrocarbons can then be recovered through the formedhigh porosity fracture and into the production casing through theunsealed perforations. In some embodiments, the diverting agents shoulddegrade or be removed before the onsite of production. In someembodiments, non-degradable material may be removed during flowback.

Some embodiments provide methods comprising: providing proppantaggregates; a diverting fluid comprising a diverting agent; and apacking fluid; introducing the proppant aggregates into a fracture thatis fluidically connected to a wellbore through a plurality ofperforations; introducing the diverting fluid into the wellbore therebyforming at least one sealed perforation and leaving at least oneunsealed perforation; and introducing the packing fluid into thefracture through the at least one unsealed perforation thereby allowingthe proppant aggregates to form a proppant bed within the fracture.

The diverting fluids of the present invention may be introduced in asubterranean formation, such that the diverting fluids carry a divertingagent downhole where the diverting agent can seal targeted perforations.In some embodiments, a majority of perforations are sealed. In someembodiments, at least 60% of the perforations are sealed. In someembodiments, at least 75% of the perforations are sealed. In someembodiments, at least 90% of the perforations are sealed.

In some embodiments, the diverting fluid of the present inventioncomprises a base fluid and a diverting agent. A base fluid willtypically include an aqueous-based fluid, but may include any fluid thatcan carry the diverting agent to the targeted perforations. Suitableaqueous-based fluids may include, but are not limited to, fresh water,saltwater (e.g., water containing one or more salts dissolved therein),brine (e.g., saturated salt water), seawater, and any combinationthereof. Oil-based fluids may also be used. An example of a suitableoil-based fluid is described in U.S. Pat. Nos. 8,119,575 and 4,316,810,the entire disclosures of which are hereby incorporated by reference.

According to some embodiments, diverting agents of the present inventioncan be used to selectively seal one or more perforations thatfluidically connect a fracture and a wellbore while leaving one or more,preferably lower, perforations unsealed. After the diverting agent hassealed targeted or desired perforations, subsequent treatment fluidsintroduced into the subterranean formation can be diverted to theremaining unsealed perforations. Generally, diverting agents areintroduced into a subterranean formation at matrix flow rates;

that is, flow rates and pressures that are below the rate/pressuresufficient to create or extend fractures in that portion of thesubterranean formation. In other embodiments, the diverting agents areintroduced into the subterranean formation at a rate/pressure sufficientto create new fractures.

In order to selectively to seal the targeted perforations, divertingagents should be added in a predetermined amount. Several factors maydetermine the exact amount of diverting agent to be used. These factorsinclude, but are not limited to, the diverting agent selected, thenumber of targeted perforations, the size of the perforations, and thelike. Generally, the diverting agent will initially seal perforationsformed closer to the top of the fracture and then later sealperforations located further toward the bottom of the fracture. Ideally,the diverting agent should be added in an amount sufficient to seal allof the targeted perforations.

In some embodiments, the diverting agent may be degradable such that itforms a non-permanent seal. Suitable examples of diverting agentsinclude, but are not limited to, polysaccharides, chitins, chitosans,proteins, orthoesters, aliphatic polyesters, poly(glycolides),poly(lactides), poly(c-caprolactones), poly(hydroxybutyrates),polyanhyrides, aliphatic polycarbonates, poly(orthoesters), poly(aminoacids), poly(ethylene oxides), polyphosphazenes, derivatives thereof,and combinations thereof. The diverting agent may also be a degradablepolymer gel blobs or chunks (described in U.S. Published PatentApplication 2011/0240297, and U.S. Pat. No. 5,680,900, the entiredisclosures of which are hereby incorporated by reference). Thediverting agent may also be a dehydrated salt. Suitable examples ofdehydrated salts that may be used in conjunction with the presentinvention include, but are not limited to, particulate solid anhydrousborate materials. Specific examples of particulate solid anhydrousborate materials that may be used include but are not limited toanhydrous sodium tetraborate (also known as anhydrous borax), andanhydrous boric acid. Such anhydrous borate materials are only slightlysoluble in water. However, with time and heat in a subterraneanenvironment, the anhydrous borate materials react with the surroundingaqueous fluid and become hydrated. The resulting hydrated boratematerials are highly soluble in water as compared to anhydrous boratematerials and as a result degrade in the aqueous fluid. Regardless ofthe type of agent chosen, the diverting agent may be present in anamount of about 0.1% to about 20% by weight of the diverting fluid.

The diverting agent may be of any physical shape including, but notlimited to, fiber, oval, spherical, platelet, and any combinationthereof. It is preferred that the diverting agent be in the form of afiber or platelet. The diverting agents may be of any size and shapecombination. The size and shape combination may depend upon, among otherfactors, the composition of the subterranean formation, the chemicalcomposition of formation fluids, the flow rate of fluids present in theformation, the effective porosity and/or permeability of thesubterranean formation, pore throat size and distribution, and the like.It is within the ability of one skilled in the art, with the benefit ofthis disclosure, to determine the size and shape of diverting agents toinclude in the methods of the present invention to achieve the desiredresults.

According to some embodiments, a packing fluid comprising proppants maybe introduced into a subterranean formation to form a relativelyhomogeneous proppant pack at the bottom of a fracture. The packing fluidmay be introduced after the targeted perforations have been sealed sothat it can be diverted to the unsealed perforations. The packing fluidcan transport the proppants into the fracture through the unsealedperforations where the proppants then settle to form a proppant pack.This proppant pack reduces the space through which the freely suspendedproppant aggregates, above, can settle. The proppant pack may reducesettling of proppant aggregates, resulting in a more even distributionof proppant aggregates within the fracture (particularly near or at thetop portion of the fracture). As such, the proppant aggregates may formmore evenly distributed proppant pillars when the fracture closes, thusresulting in high porosity fractures and/or fewer fracture closures.

In some embodiments, the packing fluid of the present inventioncomprises a carrier fluid and proppants. In other embodiments, thepacking fluid of the present invention comprises only a carrier fluid.The composition of the packing fluids may resemble commonly knownfracturing fluids. The packing fluid may also include additionaladditives such as, but not limited to, gelling agents, crosslinkingagents, gel breakers, any combinations thereof, and the like.

Proppant particulates suitable for use in the packing fluids of thepresent invention may be of any size and shape combination known in theart as suitable for use in a fracturing operation. In some embodiments,the proppants are engineered to be of a specific volume or size to carryout their desired function. In some embodiments of the present inventionit may be desirable to use substantially non-spherical proppantparticulates. Suitable substantially non-spherical proppant particulatesmay be cubic, polygonal, fibrous, or any other non-spherical shape. Suchsubstantially non-spherical proppant particulates may be, for example,cubic-shaped, rectangular shaped, rod shaped, ellipse shaped, coneshaped, pyramid shaped, or cylinder shaped. That is, in embodimentswherein the proppant particulates are substantially non-spherical, theaspect ratio of the material may range such that the material is fibrousto such that it is cubic, octagonal, or any other configuration.Substantially non-spherical proppant particulates are generally sizedsuch that the longest axis is from about 0.02 inches to about 0.3 inchesin length. In other embodiments, the longest axis is from about 0.05inches to about 0.2 inches in length. In one embodiment, thesubstantially non-spherical proppant particulates are cylindrical havingan aspect ratio of about 1.5 to 1 and about 0.08 inches in diameter andabout 0.12 inches in length. In another embodiment, the substantiallynon-spherical proppant particulates are cubic having sides about 0.08inches in length. The use of substantially non-spherical proppantparticulates may be desirable in some embodiments of the presentinvention because, among other things, they may provide a lower rate ofsettling when slurried into a fluid as is often done to transportproppant particulates to desired locations within subterraneanformations. By so resisting settling, substantially non-sphericalproppant particulates may provide improved proppant particulatedistribution as compared to more spherical proppant particulates.

Proppants suitable for use in the present invention may comprise anymaterial suitable for use in subterranean operations. Suitable materialsfor these particulates include, but are not limited to, sand, bauxite,ceramic materials, glass materials, polymer materials,polytetrafluoroethylene materials, nut shell pieces, cured resinousparticulates comprising nut shell pieces, seed shell pieces, curedresinous particulates comprising seed shell pieces, fruit pit pieces,cured resinous particulates comprising fruit pit pieces, wood, compositeparticulates, and combinations thereof. Suitable composite particulatesmay comprise a binder and a filler material wherein suitable fillermaterials include silica, alumina, fumed carbon, carbon black, graphite,mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc,zirconia, boron, fly ash, hollow glass microspheres, solid glass, andcombinations thereof. The mean particulate size generally may range fromabout 2 mesh to about 400 mesh on the U.S. Sieve Series; however, incertain circumstances, other mean particulate sizes may be desired andwill be entirely suitable for practice of the present invention. Inparticular embodiments, preferred mean particulates size distributionranges are one or more of 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60,40/70, or 50/70 mesh. It should be understood that the term“particulate,” as used in this disclosure, includes all known shapes ofmaterials, including substantially spherical materials, fibrousmaterials, polygonal materials (such as cubic materials), andcombinations thereof. Moreover, fibrous materials, that may or may notbe used to bear the pressure of a closed fracture, may be included incertain embodiments of the present invention. In certain embodiments,the particulates may be present in the treatment fluids of the presentinvention in an amount in the range of from about 0.01 pounds per gallon(“ppg”) to about 30 ppg by volume of the treatment fluid, the exactvalue depending on the treatment fluid.

Some embodiments of the present provides methods comprising: providingproppant aggregates; a diverting fluid comprising a degradable divertingagent; and a packing fluid; introducing the proppant aggregates into afracture that is fluidically connected to a wellbore through a pluralityof perforations; introducing the diverting fluid into the wellborethereby forming at least one sealed perforation and leaving at least oneunsealed perforation; introducing the packing fluid into the fracturethrough the at least one unsealed perforation thereby allowing theproppant aggregates to form a proppant bed within the fracture; andallowing the degradable diverting agent to degrade thereby unsealing theat least one perforation.

According to some embodiments, proppant aggregates may be introducedinto at least one fracture within a subterranean formation. The proppantaggregates may have any shape including, but not limited to, oval,spheroid, stringy mass, combinations thereof, and the like. As those ofordinary skill in the art will appreciate, the proppant aggregates mayhave any well-defined physical shape or may have an irregular geometry.In some embodiments, the proppant aggregates are substantially the samesize. In other embodiments, the proppant aggregates have differentsizes.

A variety of methods may be used to form proppant aggregates. Examplesof suitable methods are described in U.S. Patent Publication No.2006/0113078, filed on Dec. 1, 2004, the contents of which is herebyincorporated by reference to the extent not inconsistent with thepresent disclosure. In one example, to form proppant aggregates, aproppant slurry should be provided. Because the proppant slurry is usedto form the proppant aggregates, the proppant aggregates may havesubstantially the same composition as the proppant slurry, namely boththe proppant aggregates and the proppant slurry generally comprise abinding fluid and a filler material. A carrier fluid should also beprovided.

As used herein, the term “binding fluid” refers to a fluid that confinesthe proppant aggregate, such that when the proppant aggregate is placedinto a fracture or placed into a carrier fluid, the proppant aggregateremains a coherent body that does not generally become dispersed intosmaller bodies without application of shear. In some embodiments, thebinding fluids comprise a consolidating agent and an aqueous gel.Generally, the binding fluid should be immiscible or at least partiallyimmiscible with the carrier fluid so that the proppant aggregatesremains a coherent body when contacted by or combined with the carrierfluid. For example, in some embodiments, the proppant slurry may be usedto form a plurality of proppant aggregates, which will be suspended inthe carrier fluid. In these embodiments, the binding fluid should alloweach of the proppant aggregates to remain a coherent body when suspendedin the carrier fluid.

Suitable consolidating agents may include, but are not limited to,non-aqueous tackifying agents, aqueous tackifying agents, emulsifiedtackifying agents, silyl-modified polyamide compounds, resins,crosslinkable aqueous polymer compositions, polymerizable organicmonomer compositions, consolidating agent emulsions, zeta-potentialmodifying aggregating compositions, and binders. Combinations and/orderivatives of these also may be suitable. Nonlimiting examples ofsuitable non-aqueous tackifying agents may be found in U.S. Pat. Nos.5,853,048; 5,839,510; and 5,833,000 as well as U.S. Patent ApplicationPublication Nos. 2007/0131425 and 2007/0131422 the relevant disclosuresof which are herein incorporated by reference. Nonlimiting examples ofsuitable aqueous tackifying agents may be found in U.S. Pat. Nos.5,249,627 and 4,670,501 as well as U.S. Patent Application PublicationNos. 2005/0277554 and 2005/0274517, the relevant disclosures of whichare herein incorporated by reference. Nonlimiting examples of suitablecrosslinkable aqueous polymer compositions may be found in U.S. PatentApplication Publication Nos. 2010/0160187 and 2011/0030950 the relevantdisclosures of which are herein incorporated by reference. Nonlimitingexamples of suitable silyl-modified polyamide compounds may be found inU.S. Pat. No. 6,439,309 entitled the relevant disclosure of which isherein incorporated by reference. Nonlimiting examples of suitableresins may be found in U.S. Pat. Nos. 7,673,686; 7,153,575; 6,677,426;6,582,819; 6,311,773; and 4,585,064 as well as U.S. Patent ApplicationPublication Nos. 2010/0212898 and 2008/0006405, the relevant disclosuresof which are herein incorporated by reference. Nonlimiting examples ofsuitable polymerizable organic monomer compositions may be found in U.S.Pat. Nos. 7,819,192, the relevant disclosure of which is hereinincorporated by reference. Nonlimiting examples of suitableconsolidating agent emulsions may be found in U.S. Patent ApplicationPublication No. 2007/0289781 the relevant disclosure of which is hereinincorporated by reference. Nonlimiting examples of suitablezeta-potential modifying aggregating compositions may be found in U.S.Pat. Nos. 7,956,017 and 7,392,847, the relevant disclosures of which areherein incorporated by reference. Nonlimiting examples of suitablebinders may be found in U.S. Pat. Nos. 8,003,579; 7,825,074; and6,287,639 as well as U.S. Patent Application Publication No.2011/0039737, the relevant disclosures of which are herein incorporatedby reference. It is within the ability of one skilled in the art, withthe benefit of this disclosure, to determine the type and amount ofconsolidating agent to include in the methods of the present inventionto achieve the desired results.

Suitable aqueous gels are generally comprised of water and one or moregelling agents. In certain embodiments of the present invention, thebinding fluid is an aqueous gel comprised of water, a gelling agent forgelling the water and increasing its viscosity, and, optionally, acrosslinking agent for crosslinking the gel and further increasing theviscosity of the fluid. The increased viscosity of the gelled, or gelledand cross-linked, binding fluid, inter alia, allows the binding fluid totransport significant quantities of suspended filler material and allowsthe proppant slurry to remain a coherent mass. Furthermore, it isdesired for the aqueous gel to maintain its viscosity after placementinto the fracture in the subterranean formation. Accordingly, thecomponents of the aqueous gel should be selected so that, when exposedto downhole conditions (e.g., temperature, pH, etc.), it does notexperience a breakdown or deterioration of the gel structure nor do theproppant aggregates experience a breakdown or deterioration.

Generally, the filler material should form a stable aggregate with thebinding fluid. Filler materials suitable for use in the presentinvention may comprise a variety of proppant materials suitable for usein subterranean operations, including, but not limited to, sand (such asbeach sand, desert sand, or graded sand), bauxite; ceramic materials;glass materials (such as crushed, disposal glass material); polymermaterials; Teflon™ materials; nut shell pieces; seed shell pieces; curedresinous particulates comprising nut shell pieces; cured resinousparticulates comprising seed shell pieces; fruit pit pieces; curedresinous particulates comprising fruit pit pieces; wood; compositeparticulates, lightweight particulates, microsphere plastic beads,ceramic microspheres, glass microspheres, man-made fibers, cements (suchas Portland cements), fly ash, carbon black powder, combinationsthereof, and the like. Suitable composite materials may comprise abinder and a filler material wherein suitable filler materials includesilica, alumina, fumed carbon, carbon black, graphite, mica, titaniumdioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron,fly ash, hollow glass microspheres, solid glass, and combinationsthereof. The appropriate filler material to include in the proppantslurry depends on a number of factors, including the selected bindingfluid, the ability to control density of the binding fluid, and thestructural flexibility or firmness of the masses of the proppant slurry.For example, where the binding fluid comprises an aqueous gel, thefiller material should act, inter alia, as proppant particulates andthus should be capable of preventing the fractures from fully closing.In other embodiments, where the binding fluid comprises a curable resincomposition, the filler material is included in the proppant slurry,inter alia, to enhance the compressive strength of the proppant slurryafter curing of the resin therein. In addition to supporting thefracture, the filler material also may act to prevent leakoff of thebinding fluid into the subterranean formation.

The filler material may be provided in a wide variety of particle sizes.The average particulate sizes generally may range from about 2 mesh toabout 400 mesh on the U.S. Sieve Series; however, it is to be understoodthat in certain circumstances, other sizes may be desired and will beentirely suitable for practice of the present invention. In someembodiments, for example, where the filler material has a specificgravity of greater than 2, the filler material may be present in theproppant slurry in an amount in the range of from about 1 pound to about35 pounds per gallon of the binding fluid. In some embodiments, forexample, where the filler material has a specific gravity of less thanabout 2, the filler material may be present in the proppant slurry in anamount in the range of from about 0.01 pound to about 10 pounds pergallon of the binding fluid. One of ordinary skill in the art, with thebenefit of this disclosure, will be able to select the appropriate type,size, and amount of filler material to include in the proppant slurryfor a particular application.

Optionally, the filler material may be coated with an adhesivesubstance. As used herein, the term “adhesive substance” refers to amaterial that is capable of being coated onto a particulate and thatexhibits a sticky or tacky character such that the filler material thathas adhesive thereon has a tendency to create clusters or aggregates. Asused herein, the term “tacky,” in all of its forms, generally refers toa substance having a nature such that it is (or may be activated tobecome) somewhat sticky to the touch. Generally, the filler material maybe coated with an adhesive material where the binding fluid is not acurable resin composition. Examples of adhesive substances suitable foruse in the present invention include the consolidating agents listedabove, such as non-aqueous tackifying agents; aqueous tackifying agents;silyl-modified polyamides; curable resin compositions that are capableof curing to form hardened substances; and combinations thereof. Amongother things, the adhesive substances, in conjunction with the bindingfluid, encourage the filler materials to form aggregates, preventing thefiller material from being dispersed within the fractures, so that thefiller materials aggregate even if the binding fluid that is confiningthe filler material becomes deteriorated after prolonged exposure todownhole conditions. Adhesive substances may be applied on-the-fly,applying the adhesive substance to the filler material at the well site,directly prior to pumping the proppant slurry into the well bore.

Any suitable carrier fluid that may be employed in subterraneanoperations may be used in accordance with the teachings of the presentinvention, including aqueous gels, viscoelastic surfactant gels, oilgels, foamed gels, and emulsions. Suitable aqueous gels are generallycomprised of water and one or more gelling agents. Suitable emulsionscan be comprised of two immiscible liquids such as an aqueous liquid orgelled liquid and a hydrocarbon. Foams can be created by the addition ofa gas, such as carbon dioxide or nitrogen. In exemplary embodiments ofthe present invention, the carrier fluids are aqueous gels comprised ofwater, a gelling agent for gelling the water and increasing itsviscosity, and, optionally, a crosslinking agent for crosslinking thegel and further increasing the viscosity of the fluid. The increasedviscosity of the gelled, or gelled and cross-linked, carrier fluid,inter alia, reduces fluid loss and allows the carrier fluid to transportproppant particulates (where desired) and/or the proppant aggregates (ifnecessary). The water used to form the carrier fluid may be fresh water,saltwater, seawater, brine, or any other aqueous liquid that does notadversely react with the other components. The density of the water canbe increased to provide additional particle transport and suspension inthe present invention.

In one embodiment, predetermined volumes of proppant slurry may bepumped intermittently into the well bore so that a plurality of proppantaggregates may be introduced into the fracture. In these embodiments,the proppant slurry may be alternately pumped into the well bore withcarrier fluid. For example, a first portion of the carrier fluid may beintroduced into the well bore. After introduction of the first portion,a predetermined volume of the proppant slurry may be introduced into thewell bore. In some embodiments, the predetermined volume of the proppantslurry may be in the range of from about 0.01 gallon to about 5 gallons.However, one of ordinary skill in the art, with the benefit of thisdisclosure, will recognize that larger volumes of the proppant slurrymay be used, dependent upon, for example, the dimensions of thefracture. Once the predetermined volume of the proppant slurry has beenintroduced into the well bore, a second portion of the carrier fluid maybe introduced into the well bore, thereby forming a proppant aggregatein the well bore, the proppant aggregate spaced between the first andsecond portions. These steps may be repeated until the desired amount ofproppant aggregates have been formed and introduced into the fracture.The predetermined volumes of the proppant slurry that are beingalternately pumped may remain constant or may be varied, such that theplurality of proppant aggregates introduced into the fracture are ofvarying sizes and shapes.

In another embodiment, the proppant slurry is combined with the carrierfluid so that the proppant slurry forms a plurality of proppantaggregates in the carrier fluid. Among other things, in theseembodiments, the plurality of proppant aggregates should be suspended inthe carrier fluid, carried by the carrier fluid into the fracture, anddistributed within the fracture. In such embodiments, at least a portionof the proppant aggregates may be deposited within the fracture, forexample, after the carrier fluid's viscosity is reduced. Generally, inthese embodiments, the proppant slurry should be combined with thecarrier fluid prior to introducing the carrier fluid into the well bore.Where the proppant slurry contains a curable resin composition, theproppant slurry is preferably combined with the carrier fluid downstreamof the blending and/or pumping equipment to, among other things, reducecoating of the curable resin composition onto such equipment and tominimize the interaction of the proppant slurry and the carrier fluid.In one embodiment, the plurality of proppant aggregates are formed byshearing (or cutting) the proppant slurry as it is combined with thecarrier fluid, e.g., as it is pumped and extruded from a container intoa different container that contains the carrier fluid. In one certainembodiment where the proppant slurry is combined with the carrier fluid,predetermined volumes of the proppant slurry are intermittently injectedinto the carrier fluid that is being introduced into the well bore. Thepredetermined volumes of the proppant slurry that are beingintermittently injected into the carrier fluid may remain constant ormay be varied, such that the proppant aggregates form in the carrierfluid in varying sizes and shapes. In some embodiments, eachpredetermined volume of the proppant slurry may be in the range of fromabout 0.01 gallon to about 5 gallons. However, one of ordinary skill inthe art, with the benefit of this disclosure, will recognize that largervolumes of the proppant slurry may be used, dependent upon, for example,the dimensions of the fracture.

In another embodiment, formation of the plurality of proppant aggregatescomprises simultaneously introducing the carrier fluid and the proppantslurry into the fracture. In these embodiments, the carrier fluid andthe proppant slurry may be introduced into the fracture via separateflow paths, so at to form a plurality of proppant aggregates. Forexample, one of the fluids (e.g., the carrier fluid or the proppantslurry) may be introduced into the fracture(s) via a conduit (e.g.,coiled tubing or jointed pipe) that is disposed within the well bore,while the other fluid (e.g., the carrier fluid or the proppant slurry)may be introduced into the fracture via an annulus defined between thetubing and the casing. As the proppant slurry and the carrier fluid areco-introduced into the fracture, the plurality of proppant aggregatesshould form and be distributed within the fracture. Among other things,this may minimize interaction between the carrier fluid and theplurality of proppant aggregates and also may enhance the formation oflayers between the two fluids. One of ordinary skill, with the benefitof this disclosure, will recognize other suitable methods for formingthe proppant aggregates and introducing them into the fracture,dependent upon the particular application.

In accordance with the above described steps, the plurality of proppantaggregates should be introduced into the fracture so that the proppantaggregates are distributed through the length and height of the fracturewithout packing or stacking together. It is preferred that the proppantaggregates are randomly distributed throughout the length and height ofthe fracture. Despite the preference in forming partial monolayers ofproppant aggregates in the fracture, the potential for forming a fullmonolayer or a packed portion potion in the fracture always exists dueto, among other things, uneven distribution of the proppant aggregates,undesired accumulation of the proppant aggregates, or particle settlingat one location.

Generally, the ratio of the plurality of proppant aggregates to carrierfluid introduced into the fracture will vary, depending on thecompositions of the proppant aggregates and the carrier fluid, theclosure stress applied on the proppant aggregates, formationcharacteristics and conditions, the desired conductivity of thefracture, the amount of the carrier fluid that can be removed from thefracture, and other factors known to those of ordinary skill in the art.As will be understood by those of ordinary skill in the art, with thebenefit of this disclosure, the higher the ratio of the plurality ofproppant aggregates to carrier fluid introduced into the fracture, theless void channels or less conductive fractures will result. In someembodiments, for example, in high Young's modulus formations (e.g.,greater than about 1×10⁶ psi), the ratio of the plurality of proppantaggregates to carrier fluid introduced into the fracture is in the rangeof from about 1:9 by volume to about 8:2 by volume. In some embodiments,for example, in low Young's modulus formations (e.g., less than about5×10⁵ psi), the ratio of the plurality of proppant aggregates to carrierfluid introduced into the fracture is in the range of from about 4:6 byvolume to about 6:4 by volume.

In another embodiment, proppant aggregates may be formed and transportedto a fracture by using a fracturing fluid system comprising a carrierfluid (e.g., a gel or a crosslinked gel fluid), and solids-laden gelbodies wherein the solids are non-degradable proppant materials (in aform such as aggregates, blobs, or clusters encapsulated by a degradablegel). Optionally, the fracturing fluid system may further comprisedegradable solids-free gel bodies (in a form such as a blob, fragment,or chunk). The solid-laden gel bodies, tend to form aggregates whenplaced into a subterranean formation, such that once the gelled carrierfluid is removed, what remains are multiple, separate clusters ofsolid-laden gel bodies that act as pillars to keep the fracture proppedopen once the fracturing pressure has been released.

Gel bodies suitable for use in the present invention include thosedescribed in U.S. Patent Application Publication No. 2010/0089581, theentire disclosure of which is hereby incorporated by reference. Inaddition, the super-absorbent polymer discussed in U.S. PatentApplication Publication No. 2011/0067868, the relevant discussion ofwhich is hereby incorporated by reference, may also be suitable for useas gel bodies in the present invention. One of skill in the art willrecognize that some of the gel bodies may be designed to degrade oncethe fracture closes, while other gel bodies may be more resistant tosuch degradation long after the closing of the fracture. In someinstances, the gel used to form the solids-laden gel bodies preferablydoes not degrade under the conditions in the subterranean formationwhile the solids-free gel bodies preferably degrade after the fracturecloses.

By way of example, gel bodies of the present invention may be formedfrom swellable polymers. Preferably, the swellable particulate is anorganic material such as a polymer or a salt of a polymeric material.Typical examples of polymeric materials include, but are not limited to,cross-linked polyacrylamide, cross-linked polyacrylate, cross-linkedcopolymers of acrylamide and acrylate monomers, starch grafted withacrylonitrile and acrylate, cross-linked polymers of two or more ofallylsulfonate, 2-acrylamido-2-methyl-1-propanesulfonic acid,3-allyloxy-2-hydroxy-1-propanesulfonic acid, acrylamide, acrylic acidmonomers, and any combination thereof in any proportion. Typicalexamples of suitable salts of polymeric material include, but are notlimited to, salts of carboxyalkyl starch, salts of carboxymethyl starch,salts of carboxymethyl cellulose, salts of cross-linked carboxyalkylpolysaccharide, starch grafted with acrylonitrile and acrylate monomers,and any combination thereof in any proportion. The specific features ofthe swellable particulate may be chosen or modified to provide aproppant pack or matrix with desired permeability while maintainingadequate propping and filtering capability. These swellable particulatesare capable of swelling upon contact with a swelling agent. The swellingagent for the swellable particulate can be any agent that causes theswellable particulate to swell via absorption of the swelling agent.

In a preferred embodiment, the swellable particulate is “waterswellable,” meaning that the swelling agent is water. Suitable sourcesof water for use as the swelling agent include, but are not limited to,fresh water, brackish water, sea water, brine, and any combinationthereof in any proportion. In another embodiment of the invention, theswellable particulate is “oil swellable,” meaning that the swellingagent for the swellable particulate is an organic fluid. Examples oforganic swelling agents include, but are not limited to, diesel,kerosene, crude oil, and any combination thereof in any proportion.

Also by way of example, degradable gel bodies may be formed fromsuper-absorbent polymers. Suitable such super-absorbent polymers includepolyacrylamide, crosslinked poly(meth)acrylate, and non-soluble acrylicpolymers.

In some embodiments, the solids (proppant) used in the solids-laden gelbodies can be coated with a curable resin. The resin may cure in thesubterranean formation to consolidate the proppant of the proppant packto form a “proppant matrix.” After curing, the resin improves thestrength, clustering ability, and flow-back control characteristics ofthe proppant matrix relative to a similar proppant pack without such acurable resin. A proppant matrix may also be formed by incorporating anon-curable tackifying agent into at least a portion of the proppant.The tackifying agent can be used in addition to or instead of a curableresin.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered,combined, or modified and all such variations are considered within thescope and spirit of the present invention. The invention illustrativelydisclosed herein suitably may be practiced in the absence of any elementthat is not specifically disclosed herein and/or any optional elementdisclosed herein. While compositions and methods are described in termsof “comprising,” “containing,” or “including” various components orsteps, the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. All numbers and rangesdisclosed above may vary by some amount. Whenever a numerical range witha lower limit and an upper limit is disclosed, any number and anyincluded range falling within the range is specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Also, the terms in the claims have their plain, ordinary meaningunless otherwise explicitly and clearly defined by the patentee.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces. If there is any conflict in the usages of a word or term inthis specification and one or more patent or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

The invention claimed is:
 1. A method comprising: providing proppantaggregates; a diverting fluid comprising a diverting agent; and apacking fluid; introducing the proppant aggregates into a fracture thatis fluidically connected to a wellbore through a plurality ofperforations; introducing the diverting fluid into the wellbore therebyforming at least one sealed perforation and leaving at least oneunsealed perforation; and introducing the packing fluid into thefracture through the at least one unsealed perforation thereby allowingthe proppant aggregates to form a proppant bed within the fracture. 2.The method of claim 1, wherein the diverting agent is degradable.
 3. Themethod of claim 2, further comprising: allowing the degradable divertingagent to degrade thereby unsealing the at least one perforation.
 4. Themethod of claim 1, wherein the diverting agent is selected from thegroup consisting of: a polysaccharide, a chitin, a chitosan, a protein,an orthoester, an aliphatic polyester, a poly(glycolide), apoly(lactide), a poly(ε-caprolactone), a poly(hydroxybutyrate), apolyanhyride, an aliphatic polycarbonate, a poly(orthoester), apoly(amino acid), a poly(ethylene oxide), a polyphosphazene, anyderivative thereof, and any combination thereof.
 5. The method of claim1, wherein the diverting agent seals at least 60% of the perforationsthat fluidically connect the wellbore and the fracture.
 6. The method ofclaim 1, wherein the diverting agent seals at least 75% of theperforations that fluidically connect the wellbore and the fracture. 7.The method of claim 1, wherein the at least one unsealed perforation islocated at or near a bottom of the fracture.
 8. The method of claim 1,wherein the proppant aggregate comprises a binding fluid and a fillermaterial selected from the group consisting of: sand, bauxite, ceramicmaterial, glass material, polymer material, polytetrafluoroethylenematerial, nut shell piece, cured resinous particulate comprising a nutshell piece, seed shell piece, cured resinous particulate comprisingseed shell piece, fruit pit piece, cured resinous particulate comprisingfruit pit piece, wood, composite particulate, and any combinationthereof.
 9. The method of claim 8, wherein the filler material is coatedwith an adhesive selected from the group consisting of: a non-aqueoustackifying agent, an aqueous tackifying agent, a silyl-modifiedpolyamide, a zeta-potential modifying agent, a curable resincomposition, and any combination thereof.
 10. The method of claim 8,wherein the binding fluid comprises a curable resin composition and anaqueous gel.
 11. The method of claim 1, wherein the packing fluidcomprises proppants.
 12. A method comprising: providing proppantaggregates; a diverting fluid comprising a degradable diverting agent;and a packing fluid; introducing the proppant aggregates into a fracturethat is fluidically connected to a wellbore through a plurality ofperforations; introducing the diverting fluid into the wellbore therebyforming at least one sealed perforation and leaving at least oneunsealed perforation; introducing the packing fluid into the fracturethrough the at least one unsealed perforation thereby allowing theproppant aggregates to form a proppant bed within the fracture; andallowing the degradable diverting agent to degrade thereby unsealing theat least one perforation.
 13. The method of claim 12, wherein thediverting agent is selected from the group consisting of: apolysaccharide, a chitin, a chitosan, a protein, an orthoester, analiphatic polyester, a poly(glycolide), a poly(lactide), apoly(ε-caprolactone), a poly(hydroxybutyrate), a polyanhyride, analiphatic polycarbonate, a poly(orthoester), a poly(amino acid), apoly(ethylene oxide), a polyphosphazene, any derivative thereof, and anycombination thereof.
 14. The method of claim 12, wherein the divertingagent seals at least 60% of the plurality of perforations thatfluidically connect the wellbore and the fracture.
 15. The method ofclaim 12, wherein the diverting agent seals at least 75% of theplurality of perforations that fluidically connect the wellbore and thefracture.
 16. The method of claim 12, wherein the at least one unsealedperforation is located at or near a bottom of the fracture.
 17. Themethod of claim 12, wherein the proppant aggregate comprises a bindingfluid and a filler material selected from the group consisting of: sand,bauxite, ceramic material, glass material, polymer material,polytetrafluoroethylene material, nut shell piece, cured resinousparticulate comprising a nut shell piece, seed shell piece, curedresinous particulate comprising seed shell piece, fruit pit piece, curedresinous particulate comprising fruit pit piece, wood, compositeparticulate, and any combination thereof.
 18. The method of claim 17,wherein the filler material is coated with an adhesive selected from thegroup consisting of: a non-aqueous tackifying agent, an aqueoustackifying agent, a silyl-modified polyamide, a zeta-potential modifyingagent, a curable resin composition, and any combination thereof.
 19. Themethod of claim 17, wherein the binding fluid comprises a curable resincomposition and an aqueous gel.
 20. The method of claim 12, wherein thepacking fluid comprises proppants.